With evolution of current technology, subsea development can beat the cost of unmanned platforms with safer results
Amec Process & Energy
- Bridging drilling and gas processingshows the various elements that are required to develop a HP/HT fields using subsea facilities. They are broken down into technologies available now, those requiring minimal further development, and those requiring considerable further development.
- Recent experiences suggest the main issue in drilling HP/HT wells is the high cost,due to deep reservoirs and slow drilling near the reservoir (2 meters/day). This results in costs of £ 30 million/well.
- Chokes can be arrayed to deal with HP/HT flow.The first choke may be a fluidic device and the second and subsequent chokes could be mechanical. Cascading two or more chokes removes the problems that a single choke failure would produce in a flowline.
- Space constraints on a conventional subsea treefor 15,000 psi pressures mean that the production and annulus strings must fit within the last casing string, typically the 9-5/8-in casing. The stab seals will need to be remote stab, self energizing, and metal-to-metal. One consequence is that there is less material thickness of the web between the production and annulus bores.
- To downrate the design pressure of the flowline after the chokerequires a safe and reliable means of shutting off the flow from the well in the event of a shut-in at the platform. A subsea HIPPS method can solve the problem.
The high pressure/high temperature (HP/HT) fields in the Central Graben area of the North Sea offer considerable reserves of gas and condensate. Development in this area is proceeding using not-normally-manned fixed wellhead structures tied back to gas processing platforms.
In these water depths, it is believed subsea facilities can offer significantly lower cost and safer developments than the fixed wellhead structures. In the following, the barriers to entry for subsea developments are discussed and possible solutions offered. Some solutions will require funding. The question is asked as to whether there are sufficient fields to justify the cost.
For this article. HP/HT is described as those reservoirs where the shut-in pressure is in excess of that allowed by a 10,000 psi tree, and where the temperature is on the order of 200° C. In addition to high pressure and temperature, the reservoir fluids generally exhibit corrosive properties via the presence of carbon dioxide (CO2) and hydrogen sulfide (H2S).
To date, five HP/HT reservoirs have been located on the UK continental shelf. It is believed others have been identified in the Norwegian sector. These large reservoirs of gas and condensate offer a rich reward, but present a challenge to the subsea industry in replacing conventional fixed wellhead platforms.
A number of land-based HP/HT fields have been developed in the Mobile Bay area of the US and in some other parts of the world. To date, however, the authors are not aware of any subsea developments.
In addition to presenting onerous pressure and temperature conditions, the reservoirs are generally deep, with depths of 6,000 meters being experienced recently. These excessive depths, together with difficult geological conditions, can result in each well taking up to nine months to drill.
Assuming a rig day rate of £ 70-80,000/day, this represents a cost of typically £ 30 million per well.
To date, most operators are prepared to develop gas condensate fields using subsea facilities where 10,000 psi trees can meet the shut-in pressure. However, moving to higher pressures of up to 18,000 psi requires a step change for certain technologies.
It is believed that considerable know-how already exists in the industry for many of the components required for subsea HP/HT and in some cases, it will only require a small additional amount of development work to develop equipment and systems that can satisfy these demanding requirements.
However, there are a few areas for which a significant step change is required and these present a technological challenge and require development funding.
Among those technologies which are available in the field today are the following:
- Drilling: Facilities are available and are currently being used to drill subsea HP/HT wells. Subsea blowout preventers are available for 15,000 psi. As mentioned earlier the main issue is the high cost due to the deep reservoirs and the slow drilling rate near the reservoir (2 meters/day) resulting in costs of £ 30 million/well.
For subsea developments, a choice of semisubmersible or jackup drilling rigs exists. Development drilling operations can be conducted aboard a mobile unit along with production with less concern over safety than fixed platforms with surface trees. It is believed this choice can offer cost savings as well as improved safety. Given the extensive time to drill the wells, it is unlikely that all wells would be predrilled before the installation of the facilities.
- Subsea controls: The requirements of HP/HT subsea completions are not expected to make any demands over and above those currently used for the control of conventional subsea production. This excludes the requirement of a high integrity plant protection system (HIPPS), which will be discussed later.
- Gas processing: Assuming that the pressures will be reduced to more normal first separator pressures through the use of the chokes downstream of the trees, the platform gas processing and treatment will be undertaken at known conditions quite similar to existing major gas condensate platforms.
One area that has been identified is the tendency for HP/HT fluids to form difficult emulsions. This may require some specific processing.
Minimal developmentAmong those technologies which will required a minimum of further development are the following:
- Downhole completions: Due to the very deep wells, the weight of the tubing is significant. Also, the strength of the tubing is affected by the higher temperatures as well as the corrosive nature of the fluids. Another challenge is the amount of thermal expansion given the extended length and high temperatures.
This subject has been well covered in other technical papers and in particular, addresses other high strength, corrosion resistance materials such as titanium and alloys for this service.
- Subsea chokes: Successful land-based chokes are available for HP/HT wells. Given their dry location, they are readily accessible for inspection, maintenance and replacement, The same activities on a subsea well require expensive mobilization of an intervention vessel capable of supporting diving, remotely operated vehicle, or remotely operated transport operations, and possibly all three.
Several manufacturers and operators have been conducting trials on chokes for high differential pressure letdown and the conclusions from these trials appears to be that a single choke would have a relatively short life. Therefore, investment in the choke to minimize intervention will reduce the life of field cost.
The choke is the last pressure controlling element between the wellhead and the flowline to the platform. As the flowline is a major part of the expenditure in time and money, failure of the choke puts the flowline at risk. Failure of the flowline puts the entire production from the field at risk with major financial consequences.
One way of reducing this risk is to design the flowline for the shut-in pressure of the well. In this case, choke failure would not jeopardize the flowline. As discussed later, this would result in expensive heavy wall material which would be difficult and costly to install, An alternative to the heavy wall flowline is to cascade two or more chokes so that a single choke failure has less risk of causing flowline failure.
Common mode failure of the chokes can be prevented by using different types of choke. For example, the first choke in the cascade may be a fluidic device. The second and subsequent chokes could be mechanical devices of either fixed or adjustable type.
- High pressure flowlines: As mentioned previously, flowlines suitable for containing a well shut-in pressure of 18,000 psi at high temperatures would require extremely high wall thicknesses, such as 50 mm for a 10-in. diameter line excluding a corrosion allowance.
This relatively high thickness not only increases the cost of the material for the line but also results in a much slower offshore welding, and thus a considerably higher installation cost.
Some investigation has been undertaken in designing the lines using a limit state condition. This will reduce the wall thickness required, but only marginally. The use of the limit state design is argued from the viewpoint that this is not a design condition, but a short excursion ensuring that the line does not burst rather than being within the design codes.
- Thermal expansion: Given the relatively high flowing temperature (200° C), the amount of thermal expansion from the cold start-up situation will be larger than on normal flowlines and require additional measures to prevent upheaval buckling.
This can be overcome by additional rock dumping, installing expansion loops, or by using a pipe-in-pipe flowline with the expansion of the inner pipe restrained by the outer carrier pipe through a series of fixed bulkheads. This pipe-in-pipe technology has been used on a recent North Sea gas/condensate project and is currently being considered for the first HP/HT platform development.
- Thermal insulation: It is desirable to keep the temperature of the fluids as high as possible to assist in preventing the formation of hydrates and water/hydrocarbon condensation with attendant slugging in the lines, particularly in the risers. To reduce heat loss will require insulation at a level higher than normal and this could be achieved by the pipe-in-pipe approach mentioned previously for preventing upheaval buckling. The alternative is the use of highly efficient insulation materials wrapped around the pipe but this is likely to make installation very difficult with the reduced buoyancy.
The pipe-in-pipe approach is probably regarded as the most cost effective and could be manufactured as a bundle and towed to the field, providing the step-out distance does not exceed 6 km. This distance is the current maximum length capable of manufacture in the UK. For longer lengths there is the possibility of a connecting subsea manifold, which could be towed out with the pipe. This would add to the cost.
- Subsea isolation valves: Considerable experience has been gained to date with subsea isolation valves (SSIV). There are mixed reports about the reliability of these systems.
The challenge for HP/HT flowline SSIVs is the combination of high pressure, large diameter and the corrosive nature of the fluids. To enhance a conventional valve suitable for these requirements is regarded as an extremely heavy and expensive solution and its practicality highly questionable.
The alternative is to develop a completely different type of valve to meet these requirements, One operator has recently commissioned a valve supplier to develop an SSIV for these requirements.
- Equations of state: To be able to predict the phase behavior and physical properties of the fluids it is necessary to have reliable equations of state that can accurately predict the flowing conditions, This is particularly critical for the very high pressure situation upstream of the choke. Downstream of the choke, lower pressures will exist. Thus, the extrapolation from the normal limit is less. To date, phase behavior at pressures exceeding 400 bars is generally regarded as very questionable. This may set the upper limit for choking the flow and setting the flowline conditions.
Considerable developmentAmong those technologies which will require considerable further development are the following:
- Subsea trees: It would initially appear to be a simple task to extend the existing 10,000 psi subsea tree to 15,000 psi, since the subsea wellhead and SOP for this pressure are well established items of equipment. However, it is useful to recall that the wellhead and SOP were developed in response to a demand for high-rated drilling equipment and not as part of a coordinated scheme to produce a class of 15,000 psi equipment for subsea production.
One consequence of this piecemeal development is that the there are space limits when considering a 15,000 psi conventional tree.
The requirements for a typical dual-bore tree are that the production and annulus strings fit within the last casing string, typically the 9-5/8-in casing.
The stab seals on a 15,000 psi subsea tree will need to be remote stab, self energizing, and metal-to-metal. These have their own space requirements. The consequence of these requirements is that there is less material thickness of the web between the production and annulus bores. This web is part of the pressure containing material for the production and annulus bores. The space requirements reduce the web thickness, but for the same material the increased pressure rating of the tree increases the web thickness required.
The block forging size will increase because of the additional material needed to accommodate the increased pressure rating and sizes of gates and seats. This increased block size limits the material properties that can be obtained through the block thickness. One apparent way of resolving this conflict is to change the material, but this will increase material cost and delivery time.
The recent introduction and rapid acceptance of the horizontal or spool tree presents an alternative route to the 15,000 psi subsea tree. This new tree configuration overcomes the basic limitations of space and material outlined above.
There is still some reservation about the use of plugs as a permanent seal for the vertical access bores in this tree configuration and this will increase for the 15,000 psi tree.
However, the horizontal or spool tree is at an early stage of development. When these reservations are overcome, the authors believe that the horizontal or spool tree will offer a cost effective route to the 15,000 psi subsea tree.
- Subsea HIPPS: To downrate the design pressure of the flowline after the choke requires a safe and reliable means of shutting off the flow from the well in the event of a shut-in at the platform. The HIPPS method has been extensively used on platforms and land-based pipelines to avoid installation of expensive pressure relief systems to limit the design pressure.
However, a subsea HIPPS system has not yet been installed.
The delay in implementation is possibly due to the limited industry acceptance and reluctance by vendors to develop existing valves and actuators to meet faster closure speeds with the required redundancy.
Part of the vendors' reluctance comes from the fact that they do not perceive a large enough market to justify the expenditure required to develop components. An additional market for a subsea HlPPS system to help offset this expenditure could be the application of connecting high pressure rated pipelines to existing lower rated export pipelines.
Assuming that subsea chokes are used to reduce the pressure immediately downstream of the tree to more normal flowing conditions the only missing pieces to proceed with a subsea development are a subsea tree for 15,000 psi and a subsea HlPPS system. All the other technologies are either available or are currently being developed for platform-based developments.
The authors are aware of various developments currently being undertaken by specialist tree and control system vendors to meet these requirements but are not fully conversant with their current status. Much of that work is being undertaken on a confidential basis.
The development costs likely to be expended in producing this equipment to meet these critical missing areas is likely to be significant. In the past, suppliers have been prepared to finance such work in-house, as the number of potential orders has justified this investment.
However, to date only five UKCS HP/HT fields have been identified to date. This results in a very limited market, although there are possibilities in the Norwegian Sector in the future. Hence, the question has to be asked as to whether the numbers of orders likely for this equipment will justify the development costs. This decision is even more marginal given the fact that these fields can (and are) be developed using fixed wellhead structures. Accordingly, the cost of developing the technology for subsea facilities has to considerably less than the equivalent fixed wellhead platform over the life cycle cost of the field (CAPEX +OPEX)).
In addition to cost, it can be strongly argued that the subsea solution offers an intrinsically safer option than the minimum visit platform.
The development of HP/HT fields using subsea technology is regarded as technically feasible and prevents a challenge to the industry. The industry has a high reputation for taking on such challenges and developing solutions which can make these developments viable.
The only question at this time is whether the cost benefit is really there, given the limited number of developments over which to offset the development costs. From a personnel safety viewpoint, subsea offers a safer system overall.
Editor's Note: This article was presented in a conference entitled "Exploiting Recent Advances in Subsea Technology," held in Aberdeen, Scotland, March 28-29, 1995.
Copyright 1995 Offshore. All Rights Reserved.